UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

Commission File Number: 000-50107 

 

DAYBREAK OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)

                                       

 

 

(509) 232-7674

(Registrant’s telephone number, including area code)

 

(Former name, former address and former fiscal year, if changed since last report)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  þ  Yes ¨  No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).                                        Yes þ        No¨ 

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨Yes þNo  

  

 

At January 12, 2012 the registrant had 48,787,769 outstanding shares of $0.001 par value common stock.

 

 

 

 

TABLE OF CONTENTS

 

 

PART I - FINANCIAL INFORMATION

 

 

 

PART I

FINANCIAL INFORMATION

 

 

 

DAYBREAK OIL AND GAS, INC.

Balance Sheets - Unaudited

3

 

 

 

DAYBREAK OIL AND GAS, INC.

Statements of Operations - Unaudited

 

 

DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows - Unaudited

5

 

DAYBREAK OIL AND GAS, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

 

 

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

 

Organization

 

Originally incorporated on March 11, 1955, as Daybreak Uranium, Inc. under the laws of the State of Washington, the Company was organized to explore for, acquire, and develop mineral properties in the Western United States.  In March 2005, the Company decided to enter the oil and gas exploration industry, and on October 25, 2005, the shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (the “Company” or “Daybreak”) to better reflect the business of the Company.

 

All of the Company’s oil and gas production is sold under contracts which are market-sensitive.  Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

 

Basis of Presentation

 

The accompanying unaudited interim financial statements and notes for the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q for quarterly reports under Section 13 or 15 (d) of the Securities Exchange Act of 1934 (the “Exchange Act”).  Accordingly, they do not include all of the information and footnote disclosures normally required by accounting principles generally accepted in the United States of America for complete financial statements. 

 

In the opinion of management, all adjustments considered necessary for a fair presentation have been included and such adjustments are of a normal recurring nature.  Operating results for the nine months ended November 30, 2011 are not necessarily indicative of the results that may be expected for the fiscal year ending February 29, 2012.

 

These financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended February 28, 2011.

 

Use of Estimates

 

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions.  These estimates and assumptions may affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and revenues and expenses during the reporting period.  Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:

·         The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any 
 impairment of proved properties;

·         The valuation of unproved acreage and proved oil and gas properties to determine the amount of any impairment of oil and gas properties;

·         Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment; and

·         Estimates regarding abandonment obligations.

 

 

NOTE 2 — GOING CONCERN

 

Financial Condition  

 

The Company’s financial statements for the nine months ended November 30, 2011 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  The Company has incurred net losses since entering the oil and gas exploration industry and as of November 30, 2011 has an accumulated deficit of $23,229,155 and a working capital deficit of $2,676,696 which raises substantial doubt about the Company’s ability to continue as a going concern.

 

Management Plans to Continue as a Going Concern  

 

The Company continues to implement plans to enhance its ability to continue as a going concern.  Daybreak currently has a net revenue interest in 11 producing wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”).  The revenue from these wells has created a steady and reliable source of revenue for the Company.  Daybreak’s average net revenue interest in these wells is 29.85%.  The Company’s average working interest is 40.15% for these same wells. 

 

The Company anticipates revenues will continue to increase as it participates in the drilling of more wells in California.  Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow and funding opportunities. 

 

The Company’s sources of funds in the past have included the debt or equity markets and, while the Company does have positive cash flow from its oil and gas properties, it has not yet established a positive cash flow on a company-wide basis.  It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future.   

 

The Company’s financial statements as of November 30, 2011 do not include any adjustments that might result from the inability to implement or execute the plans to improve its ability to continue as a going concern.

 

 

NOTE 3 — RECENT ACCOUNTING PRONOUNCEMENTS

 

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06).  This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements.  In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements).  The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company’s operating results, financial position or cash flows and related disclosures.

 

No other new accounting pronouncements issued or effective has had, or is expected to have, a material impact on the Company’s financial statements.

 

7

 

NOTE 4 — CONCENTRATION OF CREDIT RISK

 

Substantially all of the Company’s accounts receivable result from crude oil sales or joint interest billings to its working interest partners.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors.  Accounts receivable are generally not collateralized.  Allowances for doubtful accounts at November 30, 2011 and February 28, 2011 relate to amounts due from joint interest owners of projects in which the Company no longer participates. 

 

At the Company’s East Slopes Project, there is only one buyer available for the purchase of oil production.  At November 30, 2011, one customer represented 100% of crude oil sales receivable.

 

 

NOTE 5 — OIL AND GAS PROPERTIES

 

Oil and gas property balances at November 30, 2011 and February 28, 2011 are set forth in the table below.

 

 

 

NOTE 6 —  ACCOUNTS PAYABLE

 

On March 1, 2009, the Company became the operator for its East Slopes Project.  Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project’s four earning wells.  The Company subsequently sold the same 25% working interest on June 11, 2009.  Approximately $317,034 of the $1.5 million default remains unpaid and is included in the November 30, 2011 accounts payable balance.

 

 

NOTE 7 — LINE OF CREDIT

 

The Company has an $890,000 credit line for working capital purposes with UBS Bank USA ("UBS") established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of the Company’s President and Chief Executive Officer.  At November 30, 2011, the Company had an outstanding balance of $875,713 with an unused borrowing capacity of $14,287 on the line of credit.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.    

 

 

NOTE 8 — SHORT-TERM AND LONG-TERM BORROWINGS

 

Short-Term

 

On September 17, 2010, the Company exercised a preferential right to acquire an additional 16.67% working interest in its East Slopes Project from another working interest owner.  The Company financed the additional working interest purchase by issuing, to a third party, Well Works, LLC (“Well Works”), a one-year convertible secured promissory note for the principal amount of $750,000 (the “Well Works Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing.  Interest expense related to the Well Works Loan for the nine months ended November 30, 2011 was $200,358.

 

 

Well Works may convert up to 50% of the unpaid principal balance into the Company’s Common Stock at a conversion price of $0.16 per share at any time prior to the Well Works Loan being paid in full. 

 

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project.  Furthermore, as a condition precedent to the Well Works Loan, the Company entered into a Technical and Consulting Services Agreement dated September 17, 2010 (the “Consulting Services Agreement”) with Well Works, whereby Daybreak would provide operating, engineering and technical consulting to Well Works for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for Well Works. 

 

The Company also issued 250,000 shares of the Company’s Common Stock to Well Works as a loan origination fee.  The fair value of these shares amounted to $23,750 which was deferred and fully amortized over the original term of the Well Works Loan.  Amortization expense for the nine months ended November 30, 2011 amounted to $11,875.  The loan origination fees were fully amortized as of November 30, 2011. 

 

As additional consideration for the Well Works Loan, the Company executed an Assignment of Net Profits Interest dated September 17, 2010 (the “Assignment of Net Profits Interest”) in favor of Well Works, whereby Daybreak assigned two percent of the net profits realized by the Company on its leases in the East Slopes Project.  The fair value of the two percent net profits interest was determined to be $60,210 and was recognized as a discount to the debt.  The debt discount was deferred and fully amortized over the original term of the Well Works Loan.  Amortization expense for the nine months ended November 30, 2011 amounted to $30,105.  The debt discount was fully amortized as of November 30, 2011.

 

The Company analyzed the Well Works Loan for derivative accounting consideration and determined that derivative accounting does not apply to this instrument.

 

A Loan Extension Agreement (the “Loan Extension Agreement”) between Well Works and the Company was executed on September 19, 2011 extending the Well Works Loan for a period of 30 days.  As compensation for the extension, Daybreak agreed to pay a fee to Well Works of $50,000 and pay interest and legal fees of $16,105 in aggregate. 

 

On October 24, 2011, Well Works and the Company executed a Forbearance Agreement whereby Daybreak requested that Well Works forbear from exercising its rights and remedies under the Well Works Loan and the Loan Extension Agreement from October 19, 2011 to November 10, 2011 (the “Forbearance Period”).  The Company agreed to pay interest and legal fees of $21,253 in aggregate during the Forbearance Period.  In addition, the Company assigned to Well Works a 3% overriding royalty interest proportionately reduced to Daybreak’s interest in all its leases in the East Slopes Project effective November 1, 2011.  Furthermore, Daybreak and Well Works agreed to cancel, in its entirety, the Assignment of Net Profits Interest.  Finally, the Consulting Services Agreement was extended until November 10, 2012.

 

On November 11, 2011, Well Works and the Company executed a new Forbearance Agreement further extending the date of the payoff from November 11, 2011 to November 18, 2011.  As compensation for the extension, Daybreak agreed to pay a fee of $12,500 plus interest due of $3,353 on the entire outstanding balance of the Well Works Loan from November 11, 2011 to November 18, 2011 at an 18% per annum default interest rate.

 

On November 18, 2011, the Company made a payment to Well Works of $600,000 thereby reducing the outstanding balance owed on the Well Works Loan and associated loan documents to $253,581.

 

 

On November 19, 2011 Well Works and the Company executed a new Forbearance Agreement (the “Forbearance Agreement II”) further extending the date of the payoff from November 18, 2011 to December 20, 2011 (the “Termination Date”).  Daybreak agreed to pay an extension fee of 20% on the outstanding balance of the Well Works Loan, associated fees and interest as of November 19, 2011, or $50,716 plus legal fees of $4,000.  Furthermore, interest is payable on the entire outstanding balance of $308,297 for the 30-day period at the default interest rate of 18% per annum, resulting in additional interest of $4,561 for a total balance of $312,858 due on or before the Termination Date.

 

If the Company is unable to pay on or before the Termination Date all amounts owed under the Forbearance Agreement II, there shall be an additional late fee of $250,000 and an increase in the default interest rate from 18% per annum to 24% per annum (2% per month) until all amounts have been repaid.

 

The Company and Well Works further agreed that the Consulting Services Agreement shall have its term extended until December 20, 2012.

 

Short-Term (Related Party)

 

On June 20, 2011, the Company issued a $200,000 non-interest bearing note to the Company’s President and Chief Executive Officer.  The term of the note provided for repayment on or before June 30, 2011, or such other date as may be agreed to by the Company and its President.  The Company and its President have agreed that repayment will be made upon the successful completion of financing.

 

Proceeds from the note were used to meet the escrow requirement on a loan commitment from a third party that was announced in June 2011.  The escrow requirement amount is reflected as an account receivable on the Balance Sheet and will be refunded to the Company upon closing. 

 

Long-Term

 

On March 16, 2010, the Company closed its private placement of 12% Subordinated Notes (the “Notes”) to 13 accredited investors resulting in total gross proceeds of $595,000.  The note principal is payable in full at the maturity date of the Notes, which is January 29, 2015.  The Notes are subject to an annual interest rate of 12%, payable semi-annually.  Prior to the maturity date, all or part of the outstanding principal balance of the Notes and all accrued and unpaid interest may be prepaid by Daybreak at any time after January 29, 2012, without penalty, premium or additional fee.  On the maturity date, the Company may elect a mandatory conversion of the unpaid principal and interest into the Company’s Common Stock at a conversion rate equal to 75% of the average closing price of the Company’s Common Stock over the 20 consecutive trading days preceding December 31, 2014.  A $250,000 Note was sold to a related party, the Company’s President and Chief Executive Officer.  The terms and conditions of the related party Note were identical to the terms and conditions of the other accredited investors’ Notes.  

 

Two Common Stock purchase warrants were issued for every dollar raised through the private placement resulting in 1,190,000 warrants being issued. The warrants have an exercise price of $0.14 and expire on January 29, 2015.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $116,557 using the following weighted-average assumptions: a risk free interest rate of 2.33%; volatility of 147.6%; and dividend yield of 0.0%.  The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method.  Amortization expense for the nine months ended November 30, 2011 was $13,850.  Unamortized debt discount amounted to $85,256 as of November 30, 2011.

 

The Company analyzed the Notes and warrants for derivative accounting consideration and determined that derivative accounting does not apply to these instruments.

 

NOTE 9 — STOCKHOLDERS EQUITY DEFICIT

 

Series A Convertible Preferred Stock

 

The Company is authorized to issue up to 10,000,000 shares of $0.001 par value preferred stock.  The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as “Series A Convertible Preferred Stock” (“Series A Preferred”), with a $0.001 par value, of which 906,565 shares were issued and outstanding as of November 30, 2011.  The Series A Preferred can be converted by the shareholder at any time into three shares of the Company’s Common Stock.  

 

During the three and nine months ended November 30, 2011, there were no conversions of Series A Preferred to the Company’s Common Stock.

  

Holders of Series A Preferred earn a 6% annual cumulative dividend based on the original purchase price of the shares.  Accumulated dividends do not bear interest and as of November 30, 2011, accumulated and unpaid dividends amounted to $1,094,614.  Dividends may be paid in cash or Common Stock at the discretion of the Company and are payable upon declaration by the Company’s Board of Directors.  Dividends are earned until the Series A Preferred is converted to Common Stock.  No payment of dividends has been declared as of November 30, 2011.

 

Dividends earned on the Series A Preferred for each fiscal year since issuance and the nine months ended November 30, 2011 are set forth in the table below:

 

 

Common Stock

 

The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock, of which 48,787,769 shares were issued and outstanding as of November 30, 2011. For the three and nine months ended November 30, 2011, no shares of the Company’s Common Stock were issued.  However, 3,830 shares of the Company’s Common Stock relating to the 2009 Plan were returned to the Company during the nine months ended November 30, 2011 as discussed in Note 11 below.

 

 

NOTE 10 —  WARRANTS

 

Warrants outstanding and exercisable as of November 30, 2011 are set forth in the table below:

 

 

11

 

There were no warrants issued or exercised during the three and nine months ended November 30, 2011.  For the nine months ended November 30, 2011, a total of 6,963,133 warrants expired.  Expired warrants include 4,013,602 and 2,799,530 warrants that were issued to accredited investors in private placements of the Company’s Common Stock and Series A Preferred that occurred in the Spring of 2006 and July of 2006 respectively, and 150,001 that expired during the three months ended November 30, 2011, that were issued in October 2007 for an extension on convertible debentures.

 

The outstanding warrants as of November 30, 2011 have a weighted average exercise price of $0.68, a weighted average remaining life of 2.24 years, and an intrinsic value of $-0-.

 

 

NOTE 11 —  RESTRICTED STOCK AND RESTRICTED STOCK UNIT PLAN

 

On April 6, 2009, the Board of Directors of the Company approved the 2009 Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of the Company and its affiliates to be eligible to receive restricted stock and restricted stock unit awards (“Awards”).  Subject to adjustment, the total number of shares of the Company’s Common Stock that will be available for the grant of Awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an Award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.

 

For the nine months ended November 30, 2011, an aggregate of 912,499 shares vested and 3,830 shares were returned to the 2009 Plan.  At November 30, 2011, a total of 1,003,830 Common Stock shares remained available for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan activity is set forth in the table below:

 

 

For the nine months ended November 30, 2011, the Company recognized compensation expense related to the above restricted stock grants of $68,414.  Unamortized compensation expense amounted to $64,879 as of November 30, 2011.

 

 

NOTE 12 —  INCOME TAXES

 

Reconciliation between actual tax expense (benefit) and income taxes computed by applying the U.S. federal income tax rate and state income tax rates to income from continuing operations before income taxes is as follows:

 

 

 

12

 

Tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are presented below:

 

 

At November 30, 2011, the Company had estimated net operating loss carryforwards for federal and state income tax purposes of approximately $15,345,067, which will begin to expire, if unused, beginning in 2024.  The valuation allowance increased approximately $294,364 for the nine months ended November 30, 2011 and increased $471,569 for the year ended February 28, 2011.  Section 382 of the Internal Revenue Code places annual limitations on the Company’s net operating loss carryforward.

 

The above estimates are based on management’s decisions concerning elections which could change the relationship between net income and taxable income. Management decisions are made annually and could cause the estimates to vary significantly.

 

 

NOTE 13 — COMMITMENTS AND CONTINGENCIES

 

Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities.  At the current time, the Company is not involved in any lawsuits or claims.  While the ultimate outcome of any future contingency is not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.

 

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment.  These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages.  In some instances, the Company may be directed to suspend or cease operations in the affected area.  The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

 

The Company is not aware of any environmental claims existing as of November 30, 2011.  There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.

 

 

 

 

13

 

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Cautionary Statement Regarding Forward-Looking Statements

 

Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) are intended to be covered by the safe harbor provided for under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.

 

Some statements contained in this Form 10-Q report relate to results or developments that we anticipate will or may occur in the future and are not statements of historical fact.  All statements other than statements of historical fact contained in this MD&A report are inherently uncertain and are forward-looking statements.  Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will” and similar expressions identify forward-looking statements.  Examples of forward-looking statements include statements about the following:

·         Our future operating results;

·         Our future capital expenditures;

·         Our future financing;

·         Our expansion and growth of operations; and

·         Our future investments in and acquisitions of oil and natural gas properties.

 

We have based these forward-looking statements on assumptions and analyses made in light of our experience and our perception of historical trends, current conditions, and expected future developments.  However, you should be aware that these forward-looking statements are only our predictions and we cannot guarantee any such outcomes.  Future events and actual results may differ materially from the results set forth in or implied in the forward-looking statements.  Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

·         General economic and business conditions;

·         Exposure to market risks in our financial instruments;

·         Fluctuations in worldwide prices and demand for oil and natural gas;

·         Our ability to find, acquire and develop oil and gas properties;

·         Fluctuations in the levels of our oil and natural gas exploration and development activities;

·         Risks associated with oil and natural gas exploration and development activities;

·         Competition for raw materials and customers in the oil and natural gas industry;

·         Technological changes and developments in the oil and natural gas industry;

·         Legislative and regulatory uncertainties, including proposed changes to federal tax laws, and climate change legislation, and potential environmental
liabilities;

·         Our ability to continue as a going concern;

·         Our ability to secure financing under any commitments as well as additional capital to fund operations; and

·         Other factors discussed elsewhere in this Form 10-Q and in our public filings, press releases and discussions with Company management. 

 

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  We specifically undertake no obligation to publicly update or revise any information contained in any forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law. 

 

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

 

 

Introduction and Overview

 

The following MD&A is management’s assessment of the historical financial and operating results of the Company for the three and nine month periods ended November 30, 2011 and November 30, 2010 and of our financial condition as of November 30, 2011, and is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes included elsewhere in this Form 10-Q and in our audited financial statements and notes included in our Annual Report on Form 10-K for the fiscal year ended February 28, 2011.  Unless otherwise noted, all of our discussion refers to continuing operations at our East Slopes Project in Kern County, California. 

 

We are an independent oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.

 

Plan of Operation

 

Our longer-term success depends on, among many other factors, the acquisition and drilling of commercial grade oil and gas properties and on the prevailing sales prices for oil and natural gas along with associated operating expenses.  The volatile nature of the energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices would have a material adverse effect on our results of operations and financial condition.  Our operations are focused on identifying and evaluating prospective oil and gas properties and funding projects that we believe have the potential to produce oil or gas in commercial quantities.  We are in the process of developing a multi-well oilfield project in Kern County, California and have participated in the drilling of 11 oil wells that have achieved commercial production.   

 

Kern County, California (East Slopes Project)

 

We believe the Company is now well positioned to expand its operations in the East Slopes Project.  We currently have production from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek properties.  The Sunday and Bear properties each have four producing wells.  The Black property is the smallest of all currently producing reservoirs, and we will most likely drill only one or two more development wells at this property.  The Ball and Dyer Creek properties were put on production in late October 2010.  There are several other similar prospects on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics.  Some of these prospects, if successful, would utilize the Company’s existing production facilities.  In addition to the current field development, there are several other exploratory prospects that have been identified from seismic data, which we plan to drill in the future.

 

Sunday Property

 

In November 2008, we made our initial oil discovery drilling the Sunday #1 well.  The well was put on production in January 2009.  Production is from the Vedder sand at approximately 2,000 feet.  During 2009, we drilled three development wells including one horizontal well.  The Sunday reservoir is estimated to be approximately 34.6 acres in size with the potential for at least three more development wells to be drilled in the future.  With the acquisition of an additional 16.67% working interest in the East Slopes Project in September 2010, we have a 41.67% working interest with a 29.0% net revenue interest in the Sunday #1 well.  We continue to have a 37.5% working interest with a 27% net revenue interest in each of the Sunday #2 and #3 wells.  We also have a 37.5% working interest with a 30.1% net revenue interest in the Sunday #4H well.

 

 

Bear Property

 

In February 2009, we made our second oil discovery drilling the Bear #1 well, which is approximately one mile northwest of our Sunday discovery.  The well was put on production in May 2009.  Production is from the Vedder sand at approximately 2,200 feet.  In December 2009, we began a development program by drilling and completing the Bear #2 well.  In April 2010, we successfully drilled and completed the Bear #3 and the Bear #4 wells.  The Bear reservoir is estimated to be approximately 62 acres in size with the potential for at least three more development wells to be drilled in the future, including one planned for the spring of 2012.  With the acquisition of an additional 16.67% working interest in the East Slopes Project in September 2010, we have a 41.67% working interest with a 29.0% net revenue interest in each of the Bear wells in this property.

 

Black Property

  

The Black property was acquired through a farm-in arrangement with a local operator.  The Black property is just south of the Bear property on the same fault system.  The Black #1 well was completed and put on production in January 2010.  Production is from the Vedder sand at 2,150 feet.  The Black reservoir is estimated to be approximately 13.4 acres in size with the potential for up to two more development wells to be drilled in the future.  We have a 37.5% working interest with a 29.8% net revenue interest in this property.

 

Sunday Central Processing and Storage Facility

 

The oil produced from our acreage is considered heavy oil.  The oil ranges from 14°  to 16°  API gravity.  All of our oil from the Sunday, Bear and Black properties is processed, stored and sold from the Sunday Central Processing and Storage Facility.  The oil must be heated to separate and remove water to prepare it to be sold.  We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines.  As a result, our average operating costs have been reduced from over $40 per barrel to a monthly average of approximately $18 per barrel of oil for the nine months ended November 30, 2011.  By having this central facility and permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.

 

Ball Property

 

The Ball #1-11 well was put on production in late October 2010.  Our 3-D seismic data indicates a reservoir approximately 37.5 acres in size with the potential for at least two development wells to be drilled in the future.  Production from the Ball #1-11 well is being processed at the Dyer Creek production facility.  We have a 41.67% working interest with a 34.69% net revenue interest in this property.  We expect to drill at least one development well at this property during 2012.  

 

Dyer Creek Property

 

The Dyer Creek #67X-11 (“DC67X”) well was also put on production in late October 2010.  This well is producing from the Vedder sand and is located to the north of the Bear property on the same trapping fault.  The Dyer Creek property has the potential for at least one development well in the future.  Production from the DC67X well is also being processed at the Dyer Creek production facility.  We have a 41.67% working interest with a 34.69% net revenue interest in this property.

 

Dyer Creek Processing and Storage Facility

 

The Dyer Creek Processing and Storage Facility serves the Ball and Dyer Creek properties and includes previously abandoned infrastructure that we have refurbished.  We have completed the installation of electrical service to this location, thereby reducing operating costs through the elimination of rental equipment for power generation.  The oil produced into this facility has a similar API gravity to the oil at the Sunday production facility and the oil must also be heated to separate and remove water in preparation for sale.

 

 

Bull Run Prospect

 

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Etchegoin and Santa Margarita sands located between 800 and 1,200 feet deep.  We drilled an exploratory well on this prospect in December 2011 that was determined to be not viable for commercial production and the well was plugged and abandoned.  Utilizing the data received from this well, we expect to drill another exploratory well on this prospect during 2012.  The Bull Run wells will require a pilot steam flood and additional production facilities.  We have a 41.67% working interest in this prospect.

 

Glide-Kendall Prospect

 

This prospect is also located in the southern portion of our acreage position.  The drilling targets are the Olcese and Eocene sands between 1,000 and 2,000 feet deep.  We plan to drill an exploratory well in the late spring of 2012.  We have a 41.67% working interest in this prospect.

 

Sherman Prospect

 

This prospect is located in the southern portion of our acreage position.  The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000 feet deep.  We plan to drill an exploratory well in 2012.  We have a 41.67% working interest in this prospect.

 

Breckenridge-Chimney Prospect

 

This prospect is located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,000 and 2,500 feet deep.  We plan to drill an exploratory well in 2012.  We have a 41.67% working interest in this prospect.

 

Tobias Prospect

 

This prospect is also located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,000 and 2,500 feet deep.  We plan to drill an exploratory well in 2012.  We have a 41.67% working interest in this prospect.

 

Production, Revenue and LOE

 

Our net sales volume, revenue and lease operating expenses (“LOE”) at the East Slopes Project for the last five quarters ended November 30, 2011 are set forth in the following table:

 

 

 

Three Months Ended November 30, 2011 compared to the Three Months Ended November 30, 2010

 

The following discussion compares our operating results for the three month periods ended November 30, 2011 and November 30, 2010 at our East Slopes Project.

 

Revenues.  Revenues are derived entirely from the sale of our share of oil production.  We realized the first revenues from producing wells in our East Slopes Project during February 2009.  The price we receive for oil sales is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, OK contracts, less deductions that vary by grade of crude oil sold.  Historically, the sale price we receive for California oil sales has been less than the quoted WTI price.  For the three months ended November 30, 2010 the average monthly WTI price was $78.40 and the average monthly sale price was $73.85, resulting in a discount of 5.8% from average monthly WTI pricing.  For the three months ended November 30, 2011 the average monthly WTI price was $89.67 and the average monthly sale price was $107.80, resulting in a premium that was 20.2% higher than the average monthly WTI pricing. 

 

Revenues at our East Slopes Project for the three months ended November 30, 2011 increased $31,848 or 12.3% to $290,912 in comparison to revenue of $259,064 for the three months ended November 30, 2010.  The average monthly sale price of a barrel of oil for the three months ended November 30, 2011 was $107.80 in comparison to $73.85 for the three months ended November 30, 2010.  The increase of $33.95 or 45.97% in the average monthly sale price of a barrel of oil accounted for 100% of the revenue increase from the comparative three month period ended November 30, 2010. 

 

At our East Slopes Project, production for the three months ended November 30, 2011 was from 11 wells with a total of 929 well days in comparison to production from 11 wells with a total of 873 well days for the three months ended November 30, 2010.  The Ball #1-11 and Dyer Creek #67X-11 wells were on production for 35 and 31 days, respectively, for the three months ended November 30, 2010.  Our net share of production for the three months ended November 30, 2011 was 2,699 barrels in comparison to 3,508 barrels for the three months ended November 30, 2010, which was a decrease in production of 809 barrels or 23.1% from the comparative three month period ended November 30, 2010.  This decrease is due to normal production decline in our oil wells.  A table of our revenues is set forth below:

 

Operating Expenses.  Total  operating expenses for the three months ended November 30, 2011 decreased by $142,323 or 21.8% to $510,646 in comparison to $652,969 for the three months ended November 30, 2010.  Significant decreases of $175,129 or 30.3% in aggregate occurred in depreciation, depletion and amortization (“DD&A”) expenses and general and administrative (“G&A”) expenses.  However these decreases were partially offset by an increase of $32,806 or 43.3% in aggregate for production expenses and exploration and drilling expenses.  

 

Operating expenses for the three months ended November 30, 2011 and 2010 are set forth in the table below:

 

 

 

Production expenses include expenses directly associated with the generation of oil and gas revenues, road maintenance and well workover expenses.  For the three months ended November 30, 2011, these expenses increased by $9,682 or 17.1% to $66,460 in comparison to $56,778 for the three months ended November 30, 2010.  The increase in production expenses is directly related to recognition of property taxes from a prior year of $13,497 for the East Slopes Project during the three months ended November 30, 2011.  Production expenses represented approximately 13.0% of total operating expenses.

 

Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  For the three months ended November 30, 2011 these expenses increased $23,124 or 122.1%, to $42,062 in comparison to $18,938 for the three months ended November 30, 2010.  Exploration and drilling expenses for the three months ended November 30, 2011, increased primarily as a result of dry hole expense of $22,213 resulting from the unsuccessful Bull Run 13X-23 exploratory well.  Exploration and drilling expenses represented approximately 8.2% of total operating expenses.

 

DD&A expense relating to equipment, proven reserves and property costs, along with impairment are another component of operating expenses.  DD&A expense decreased $90,069 or 61.4% to $56,582 for the three months ended November 30, 2011 in comparison to $146,651 for the three months ended November 30, 2010 primarily due to a larger proven reserve base used in the DD&A calculation.  DD&A expense represented approximately 11.1% of total operating expenses.    

 

G&A expenses include the salaries of seven employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company.  For the three months ended November 30, 2011, G&A expenses decreased $85,060 or 19.8% to $345,542 in comparison to $430,602 for the three months ended November 30, 2010.  Significant decreases were realized in the following areas: accounting and legal ($55,975); consulting and fundraising ($18,138); and advertising and marketing ($6,700).  Management and employee salaries, which comprised 47.0% of our G&A expense and stock compensation remained relatively unchanged for the three months ended November 30, 2011 in comparison to the three months ended November 30, 2010.  For the three months ended November 30, 2011 and 2010, we received, as Operator, administrative overhead reimbursement of approximately $18,160 and $22,537, respectively, for the East Slopes Project, which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A costs represented approximately 67.7% of total operating expenses for the three months ended November 30, 2011.

 

Interest income for the three months ended November 30, 2011 decreased $83 to $184 compared to $267 for the three months ended November 30, 2010, due to lower average cash balances.

 

Interest expense for the three months ended November 30, 2011 increased $131,344 to $188,768 in comparison to $57,424 for the three months ended November 30, 2010, primarily due to interest expense associated with the Well Works Loan discussed further in this MD&A under the caption One-Year Note Payable.

 

Due to the nature of our business, as well as the relative immaturity of the Company, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially on a quarter-to-quarter and year-to-year basis.  Production costs will fluctuate according to the number and percentage ownership of producing wells, as well as the amount of revenues being contributed by such wells.  Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects.  Likewise, the amount of DD&A expense and impairment costs will depend upon the factors cited above and the size of our reserve base.  G&A costs will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.

 

 

Nine Months Ended November 30, 2011 compared to the Nine Months Ended November 30, 2010

 

The following discussion compares our results for the nine month periods ended November 30, 2011 and November 30, 2010.  Unless otherwise referenced, these results only cover our continuing operations at the East Slopes Project.

 

Revenues.  Revenues are derived entirely from the sale of our share of oil production.  For the nine months ended November 30, 2010, the average monthly WTI price was $78.08 and the average monthly sale price was $71.18 resulting in a discount of 8.8% from average monthly WTI pricing.  For the nine months ended November 30, 2011, the average monthly WTI price was $95.80 and the average monthly sale price was $104.88 resulting in a premium that was 9.5% higher than the average monthly WTI pricing. 

 

Revenues at our East Slopes Project for the nine months ended November 30, 2011 increased $347,849 or 53.1% to $1,002,953 in comparison to revenues of $655,104 for the nine months ended November 30, 2010.  The average monthly sale price of a barrel of oil for the nine months ended November 30, 2011 was $104.88 in comparison to $71.18 for the nine months ended November 30, 2010.  The increase of $33.71 or 47.36% in the average sale price of a barrel of oil accounted for $310,244 or 89.2% of the revenue increase from the comparative nine month period ended November 30, 2010.  The revenue for the nine months ended November 30, 2010 included a special one-time revenue adjustment of approximately $104,017 in regards to the Krotz Springs well in Louisiana. 

 

Production for the nine months ended November 30, 2011 was from 11 wells with a total of 2,929 well days in comparison to production from 11 wells with a total of 2,377 well days for the nine months ended November 30, 2010.  The Ball #1-11 and Dyer Creek #67X-11 wells were on production for 35 and 31 days, respectively, for the nine months ended November 30, 2010.  Our net share of production for the nine months ended November 30, 2011 was 9,563 barrels in comparison to 9,204 barrels for the nine months ended November 30, 2010.  The increase in production of 359 barrels or 3.9% accounted for $37,605 or 10.8% of the revenue increase from the comparative nine month period ended November 30, 2010.  A table of our revenues is set forth below:

 

 

**During the nine months ended November 30, 2010, the Company received approximately $104,017 in revenue related to the Krotz Springs Field in Louisiana as a one-time adjustment to gas revenue earned in calendar years 2007, 2008 and 2009 due to well production revenue misallocation by the unitized field operator.

 

Operating Expenses.  Total operating expenses for the nine months ended November 30, 2011 decreased by $355,308 or 19.0% in comparison to the nine months ended November 30, 2010.  Significant decreases of $424,226 or 23.9% in aggregate occurred in exploration and drilling,  DD&A and G&A expenses.  However these decreases were partially offset by an increase of $60,594 in production expenses.  The remaining difference in the comparative nine month change in total operating expenses was due to a gain of $8,324 on the write-off of an asset retirement obligation for the nine months ended November 30, 2010.  

 

 

Operating expenses for the nine months ended November 30, 2011 and 2010 are set forth in the table below:

 

 

Production expenses for the nine months ended November 30, 2011 increased by $60,594 to $166,303 in comparison to $105,709 for the nine months ended November 30, 2010.  The increase in production expenses is directly related to the number of wells that were producing during the nine months ended November 30, 2011 and 2010, our percentage of working interest ownership in those wells and the recognition of property taxes from a prior year.  Additionally, for the nine months ended November 30, 2010, we received oil processing credits of approximately $35,368 from a third party that were applied against production expenses.  Production costs represented approximately 10.9% of total operating expenses.

 

Exploration and drilling expenses decreased by $65,371 or 40.1% to $97,850 for the nine months ended November 30, 2011 in comparison to $163,221 for the nine months ended November 30, 2010.  For the nine months ended November 30, 2011, we drilled one exploratory dry hole well at our Bull Run Prospect at a cost of $22,213.  Exploration and drilling costs represented approximately 6.4% of total operating expenses.

 

DD&A and impairment expenses for the nine months ended November 30, 2011 decreased $172,218 or 44.9% to $211,490 in comparison to $383.708 for the nine months ended November 30, 2010, primarily due to a larger proven reserve base used in the DD&A calculation.  DD&A expenses represented approximately 13.9% of total operating expenses.

 

G&A expenses include the salaries of seven employees, including management.  Other items included in our G&A are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, SOX compliance expenses and other administrative expenses necessary for an operator of oil and gas properties as well as for running a public company.  G&A expense decreased $186,637, or 15.2% to $1,043,858 for the nine months ended November 30, 2011 in comparison to $1,230,495 for the nine months ended November 30, 2010.  Significant decreases were realized in the following areas: consulting and fundraising ($55,213); accounting and legal ($50,559); advertising and marketing ($32,845); travel ($25,729); and shareholder services ($24,332).  Management and employee salaries, which comprise 46.7% of our G&A expense and stock compensation remained relatively unchanged for the nine months ended November 30, 2011 in comparison to the nine months ended November 30, 2010.  For the nine months ended November 30, 2011 and 2010, we received, as Operator, administrative overhead reimbursement of approximately $50,646 and $84,616, respectively, for the East Slopes Project which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A costs represented approximately 68.7% of total operating expenses for the nine months ended November 30, 2011.

 

Interest income for the nine months ended November 30, 2011 decreased $1,435 or 73.7% to $512 in comparison to $1,947 for the nine months ended November 30, 2010 due to lower average cash balances.

 

Interest expense increased $202,125 to $306,210 for the nine months ended November 30, 2011 compared to $104,085 for the nine months ended November 30, 2010, primarily due to interest expense associated with the Well Works Loan discussed further in this MD&A under the caption One-Year Note Payable.

 

 

Liquidity and Capital Resources

 

Our primary financial resource is our oil reserves base.  Our ability to fund a future capital expenditure program is dependent upon the level of prices we receive from oil sales, the success of our exploration and development program in Kern County, California, and the availability of capital resource financing.  Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the current fiscal year.

 

The Company’s financial statements for the nine months ended November 30, 2011 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  We have incurred net losses since entering the oil and gas exploration industry and as of November 30, 2011 we have an accumulated deficit of $23,229,155 and a working capital deficit of $2,676,696, which raises substantial doubt about our ability to continue as a going concern.

 

We continue to seek additional financing for our planned exploration and development activities.  We plan to obtain financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which could result in dilution of existing security holders and increased debt and leverage.  No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.

 

Changes in our capital resources at November 30, 2011 in comparison to February 28, 2011 are set forth in the table below:

 

 

Our working capital deficit increased $597,847 to ($2,676,696) at November 30, 2011 in comparison to ($2,078,849) at February 28, 2011.  The increase in the working capital deficit was principally due to an increase in our short term borrowings to meet drilling commitments and ongoing financial commitments reflected in our G&A expenses and increased payables balances.        

 

During the nine months ended November 30, 2011, we reported an operating loss of approximately $516,548 in comparison to an operating loss of approximately $1,115,688 for the nine months ended November 30, 2010.  This decrease in the operating loss of approximately $599,140 or 53.7% from the comparative nine months ended November 30, 2010 was achieved by both increasing revenue and lowering operating costs. 

 

Cash Flows

 

Our sources of funds in the past have included the debt or equity markets and, while we have positive cash flow from our oil and gas properties, we have not yet established positive cash flow on a company-wide basis.  We will need to rely on the debt or equity private or public markets, if available, to fund future operations.  Our business model is focused on acquiring exploration and development properties and also acquiring existing producing properties.  Our ability to generate future revenues and operating cash flow will depend on successful exploration and/or acquisition of oil and gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources, if available. 

 

Our expenditures consist primarily of exploration and drilling costs, production expenses, geological and engineering services and acquiring mineral leases.  Additionally, our expenses also consist of consulting and professional services, employee compensation, legal, accounting, travel and other G&A expenses which we have incurred in order to address necessary organizational activities.

 

 

The net funds provided by and (used in) each of our operating, investing and financing activities are summarized in the following table:

 

Cash Flow Provided by Operating Activities

 

Cash flow from operating activities is derived from the production of our oil and gas reserves and changes in the balances of receivables, payables or other non-oil property asset account balances.  For the nine months ended November 30, 2011, we had a positive cash flow from operating activities of $62,833, in comparison to a positive cash flow of $109,069 for the nine months ended November 30, 2010.  This decrease in positive cash flow of $46,236 was primarily the result of a decrease in accounts receivable and an increase in prepaid expenses for the nine months ended November 30, 2011.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

 

Cash Flow (Used in) Investing Activities

 

Cash flow from investing activities is derived from changes in oil and gas property and other assets account balances.  Cash used in investing activities for the nine months ended November 30, 2011 was $170,665, resulting in a decrease of $842,930 from the $1,013,595 used in investing activities for the nine months ended November 30, 2010.  This decrease in cash used in investing activities was primarily due to the lack of drilling activity that occurred during the nine months ended November 30, 2011 in comparison to the nine months ended November 30, 2010 when the Ball #1-11 and Dyer Creek #67X-11 wells were drilled.

 

Cash Flow Provided by Financing Activities

 

Cash flow from financing activities is derived from changes in equity account balances excluding retained earnings or changes in long-term liability account balances.  For the nine months ended November 30, 2011 cash flow from financing activities was $275,713 in comparison to $780,000 for the nine months ended November 30, 2010. The $275,713 balance reflects the net proceeds from the credit line after reducing the balance owed on the Well Works loan.  Financing activity for the nine months ended November 30, 2010 consisted of funds received through the sale of  the Notes ($30,000) and the Well Works Loan ($750,000). 

 

Daybreak has ongoing capital commitments to develop all of its oil and gas leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company.  A major source of capital for Daybreak in the past has been the sale of debt or equity securities in the private or public markets.  The debt or equity markets, if available to us, will continue to be capital sources for Daybreak until sustained positive cash flow has been achieved.  The current uncertainty in the credit and capital markets may restrict our ability to obtain needed capital. 

 

One-Year Note Payable

 

On September 17, 2010, we exercised a preferential right to acquire an additional 16.67% working interest in our East Slopes Project from another working interest owner.  We financed the additional working interest purchase by issuing, to a third party, Well Works, LLC (“Well Works”), a one-year convertible secured promissory note for the principal amount of $750,000 (the “Well Works Loan”), subject to an annual interest rate of 10% per annum, which was prepaid at closing. 

 

 

Well Works may convert up to 50% of the unpaid principal balance into our Common Stock at a conversion price of $0.16 per share at any time prior to the Well Works Loan being paid in full. 

 

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in our East Slopes Project.  Furthermore, as a condition precedent to the September 2010 Loan, we entered into a Technical and Consulting Services Agreement dated September 17, 2010 (the “Consulting Services Agreement”) with Well Works, whereby we will provide operating, engineering and technical consulting to the third party for a one-year period for the purpose of evaluating 22 wells in Hutchinson County, Texas for Well Works. 

 

We also issued 250,000 shares of the Company’s Common Stock to Well Works as a loan origination fee.  The fair value of these shares amounted to $23,750 which was deferred and fully amortized over the original term of the Well Works Loan.  The loan origination fees were fully amortized as of November 30, 2011. 

 

As additional consideration for the Well Works Loan, we executed an Assignment of Net Profits Interest dated September 17, 2010 (the “Assignment of Net Profits Interest”) in favor of Well Works, whereby we assigned two percent of the net profits realized by us on our leases in the East Slopes Project.  The fair value of the two percent net profits interest was determined to be $60,210 and was recognized as a discount to the debt.  The debt discount was fully amortized as of November 30, 2011.

 

The Company analyzed the Well Works Loan for derivative accounting consideration and determined that derivative accounting does not apply to this instrument.

 

A Loan Extension Agreement (the “Loan Extension Agreement”) between Well Works and Daybreak was executed on September 19, 2011 extending the Well Works Loan for a period of 30 days.  As compensation for the extension, we agreed to pay a fee to Well Works of $50,000 and pay interest and legal fees of $16,105 in aggregate. 

 

On October 24, 2011, Well Works and Daybreak executed a Forbearance Agreement whereby we requested that Well Works forbear from exercising its rights and remedies under the Well Works Loan and the Loan Extension Agreement from October 19, 2011 to November 10, 2011 (the “Forbearance Period”).  We agreed to pay interest and legal fees of $21,253 in aggregate during the Forbearance Period.  In addition, we assigned to Well Works a 3% overriding royalty interest proportionately reduced to our interest in all our leases in the East Slopes Project effective November 1, 2011.  Furthermore, Daybreak and Well Works agreed to cancel, in its entirety, the Assignment of Net Profits Interest.  Finally, the Consulting Services Agreement was extended until November 10, 2012.

 

On November 11, 2011, Well Works and Daybreak executed a new Forbearance Agreement further extending the date of the payoff from November 11, 2011 to November 18, 2011.  As compensation for the extension, we agreed to pay a fee of $12,500 plus interest due of $3,353 on the entire outstanding balance of the Well Works Loan from November 11, 2011 to November 18, 2011 at an 18% per annum default interest rate.

 

On November 18, 2011, we made a payment to Well Works of $600,000 thereby reducing the outstanding balance owed on the Well Works Loan and associated loan documents to $253,581.

 

On November 19, 2011 Well Works and Daybreak executed the Forbearance Agreement II, which further extended the date of the payoff from November 18, 2011 to the Termination Date, December 20, 2011.  We agreed to pay an extension fee of 20% on the outstanding balance of the Well Works Loan, associated fees and interest as of November 19, 2011, or $50,716 plus legal fees of $4,000.  Furthermore, interest is payable on the entire outstanding balance of $308,297 for the 30-day period at the default interest rate of 18% per annum, resulting in additional interest of $4,561 for a total balance of $312,858 due on or before the Termination Date.

 

 

If we are unable to pay on or before the Termination Date all amounts owed under the Forbearance Agreement II, there shall be an additional late fee of $250,000 and an increase in the default interest rate from 18% per annum to 24% per annum (2% per month) until all amounts have been repaid.

 

Daybreak and Well Works further agreed that the Consulting Services Agreement shall have its term extended until December 20, 2012.

 

Related Party –Note Payable

 

On June 20, 2011, we issued a $200,000 non-interest bearing note to our President and Chief Executive Officer.  The term of the note provided for repayment on or before June 30, 2011, or such other date as may be agreed to by Daybreak and our President.  Daybreak and our President have agreed that repayment will be made upon the successful completion of financing.

 

Proceeds from the note were used to meet the escrow requirement on a loan commitment from a third party that was announced in June 2011.  The escrow requirement amount is reflected as an account receivable on the Balance Sheet and will be refunded to the Company upon closing. 

 

Line of Credit

 

During the nine months ended November 30, 2011 we negotiated an $890,000 credit line for working capital purposes with UBS Bank USA, ("UBS") established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  At November 30, 2011, the Company had an outstanding balance of $875,713 with an unused borrowing capacity of $14,287 on the line of credit.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.    

 

12% Subordinated Notes

 

On March 16, 2010 we closed a private placement of 12% Subordinated Notes (the “Notes”) resulting in total gross proceeds of $595,000.  A $250,000 Note was sold to a related party, our President and Chief Executive Officer.  The terms and conditions of the related party Note were identical to the terms and conditions of the other participants’ Notes.  The Notes are subject to an annual interest rate of 12%, payable semi-annually, and mature on January 29, 2015.  Prior to the maturity date, all or part of the outstanding principal balance of the Notes and all accrued and unpaid interest may be prepaid by Daybreak at any time after January 29, 2012, without penalty, premium or additional fee.  On the maturity date, we may elect a mandatory conversion of the unpaid principal and interest into our common stock at a conversion rate equal to 75% of the average closing price of our common stock over the 20 consecutive trading days prior to December 31, 2014.  Proceeds from the sale of the notes were used to meet operating expenses and fund a portion of our development drilling program in Kern County, California.  This offering of securities was made pursuant to a private placement held under Regulation D promulgated under the Securities Act of 1933, as amended.

 

Two Common Stock purchase warrants were issued for every dollar raised through the private placement resulting in 1,190,000 warrants being issued. The warrants have an exercise price of $0.14 and expire on January 29, 2015. The fair value of the warrants was recognized as a discount to debt and is being amortized over the term of the Notes using the effective interest method.  Amortization expense for the nine months ended November 30, 2011 was $13,850.  Unamortized debt discount amounted to $85,256 as of November 30, 2011.

 

 

Changes in Financial Condition and Results of Operations

 

Cash Balance

 

We maintain our cash balance by increasing or decreasing our exploration and drilling expenditures as limited by availability of cash from operations, investments and capital resource funding.  Our cash balances were $225,261 and $57,380 as of November 30, 2011 and February 28, 2011, respectively.  The increase of approximately $167,881 was due to receipt of proceeds from our credit line as well as prepayments received from our working interest partners on future drilling, workover and infrastructure improvement projects in Kern County, California.

 

Operating Loss

 

For the nine months ended November 30, 2011, we reported an operating loss of approximately $516,548 in comparison to an operating loss of approximately $1,115,688 for the nine months ended November 30, 2010.  This reduction in the operating loss of approximately $599,140 or 53.7% from the operating loss for the nine months ended November 30, 2010 was achieved by increasing revenue and lowering operating costs.  Revenue for the nine months ended November 30, 2011 increased due to both an increase in production and an increase in the sales price of oil.  We increased production by 359 barrels of oil or 3.9% through sales from 11 producing wells.  The average price of oil increased by $33.71 or 47.36% to $104.88 per barrel for the nine months ended November 30, 2011 in comparison to $71.18 for the nine months ended November 30, 2010.

 

Operating expenses decreased by $355,308 or 19.0% to $1,519,501 for the nine months ended November 30, 2011 in comparison to $1,874,809 for the nine months ended November 30, 2010.  Exploration and drilling, DD&A and G&A expenses experienced a combined reduction of $424,226 or 23.9% in aggregate.  This reduction was offset by an increase of $60,594 in production expenses for the nine months ended November 30, 2011.

 

Net Loss

 

Since entering the oil and gas exploration industry, we have incurred recurring losses with periodic negative cash flow and have depended on external financing and the sale of oil and gas assets to sustain our operations.  A net loss of $822,246 was reported for the nine months ended November 30, 2011 in comparison to a net loss of $1,206,809 for the nine months ended November 30, 2010.  The decrease in net loss of $384,563 or 31.9% for the nine months ended November 30, 2011 was primarily due to an increase of $243,832 in revenue generated from oil sales and a reduction of $355,308 in operating expenses offset by an increase in interest expense of $202,125 in comparison to the nine months ended November 30, 2010.

 

Restricted Stock and Restricted Stock Unit Plan

 

On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted stock and restricted stock unit awards.  Subject to adjustment, the total number of shares of Daybreak’s common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.

 

We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.

 

 

For the nine months ended November 30, 2011 an aggregate of 912,499 shares vested and 3,830 shares were returned to the 2009 Plan.  At November 30, 2011, a total of 1,003,830 Common Stock shares remained available for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan activity is set forth in the table below:

 

For the nine months ended November 30, 2011, we recognized compensation expense related to the above restricted stock grants of $68,414.  Unamortized compensation expense amounted to $64,879 as of November 30, 2011.

 

Summary

 

We are continuing to execute the Company’s business plan of developing Daybreak’s acreage position in Kern County, California.  The Company will continue to focus our efforts on drilling development wells, as well as drilling several exploration wells over the next 12 months; which, coupled with the completion of our production and operating infrastructure will increase our net cash flow. 

 

We continue to seek additional financing for our planned exploration and development activities.  We plan to obtain financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which could result in dilution to existing security holders and increased debt and leverage.  No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.

 

Critical Accounting Policies

 

Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2011.

 

Off-Balance Sheet Arrangements

 

As of November 30, 2011, we did not have any off-balance sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have, a material effect on our financial position or results of operations.

 

 

 

As a smaller reporting company, we are not required to provide the information otherwise required by this Item.

 

 

ITEM 4.  CONTROLS AND PROCEDURES

 

Management’s Evaluation of Disclosure Controls and Procedures

 

As of the end of the reporting period, November 30, 2011, an evaluation was conducted by Daybreak management, including our President and Chief Executive Officer, who is also serving as our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Exchange Act.  Such disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods specified by the SEC rules and forms.  Additionally, it is vital that such information is accumulated and communicated to our management, including our President and Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures.  Based on that evaluation, our management concluded that our disclosure controls were effective as of November 30, 2011.

 

Changes in Internal Control over Financial Reporting

 

There have not been any changes in the Company’s internal control over financial reporting during the three months ended November 30, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Limitations

 

Our management does not expect that our disclosure controls or internal controls over financial reporting will prevent all errors or all instances of fraud.  A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.

 

Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected.  These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.  Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls.  The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and any design may not succeed in achieving its stated goals under all potential future conditions.

 

Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.  Because of the inherent limitation of a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

 

 

 

PART II

OTHER INFORMATION

 

 

ITEM 1.  LEGAL PROCEEDINGS

 

None.

 

 

ITEM 1A.  RISK FACTORS

 

The following two risk factors could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements and update the Risk Factors included in our Annual Report on Form 10-K for the fiscal year ended February 28, 2011.  In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements.  Except as set forth below, there have been no material changes to the risks previously disclosed in our “Risk Factors” described in Part 1, Item 1A, of the Annual report on Form 10-K for the year ended February 28, 2011, as filed with the U.S. Securities and Exchange Commission on May 26, 2011, and available at www.sec.gov.

 

The amount of our outstanding indebtedness continues to increase and our ability to make payments towards such indebtedness could have adverse consequences on future operations.

 

Our outstanding indebtedness at November 30, 2011 was approximately $4,209,661, which was comprised of the $150,000 unpaid principal balance on a $750,000 Secured Promissory Note currently due on December 20, 2011 (“Well Works Loan”); the $595,000 principal on the 12% Subordinated Notes and $3,464,661 in accounts payable, notes payable-related party and our credit line.  The level of indebtedness affects our operations in a number of ways.  We will need to use a portion of our cash flow to pay principal and interest and meet payables commitments, which will reduce the amount of funds we will have available to finance our operations.  This lack of funds could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate and could limit our ability to make funds available for other purposes, such as future exploration, development or acquisition activities.  Our ability to meet our debt service obligations and reduce our total indebtedness will depend upon our future performance.  Our future performance, in turn, is dependent upon many factors that are beyond our control such as general economic, financial and business conditions.  We cannot guarantee that our future performance will not be adversely affected by such economic conditions and financial, business and other factors.

 

The Well Works Loan is secured by a Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing Statement on the Sunday and Bear leases in the Company’s East Slopes Project.  If the Company were to default on this Loan, the Company would lose two of its primary leases.

  

Recently proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs

 

On July 28, 2011, the Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production.  Specifically, EPA’s proposed rule package includes a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities.  The proposed rules would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment.  EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012.  If finalized, these rules could require a number of modifications to our operations including the installation of new equipment.  Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

 

 

 

 

ITEM 6.  EXHIBITS

 

The following Exhibits are filed as part of the report:

 

Exhibit

Number   Description

 

10.1⁽¹⁾       Credit Line Agreement, dated October 24, 2011, by and between Daybreak Oil and Gas, Inc. and UBS Bank USA.

10.2⁽¹⁾     Loan Extension Agreement, dated September 19, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.

10.3⁽¹⁾     Forbearance Agreement, dated October 24, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.

10.4⁽¹⁾     Forbearance Agreement, dated November 11, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.

10.5⁽¹⁾     Assignment of Net Profits Interest Termination Agreement, effective October 31, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.

10.6⁽¹⁾     Override Grant Deed, effective November 1, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.

10.7⁽¹⁾     Forbearance Agreement II, dated November 19, 2011, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.

31.1⁽¹⁾     Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1⁽¹⁾     Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS⁽²⁾   XBRL Instance Document

 

101.SCH⁽²⁾  XBRL Taxonomy Schema

 

101.CAL⁽²⁾  XBRL Taxonomy Calculation Linkbase

 

101.DEF⁽²⁾   XBRL Taxonomy Definition Linkbase

 

101.LAB⁽²⁾  XBRL Taxonomy Label Linkbase

 

101.PRE⁽²⁾   XBRL Taxonomy Presentation Linkbase

 

 

 

 

 

 

(1)     Filed herewith

(2)     Furnished herewith

 

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

                                                                                 DAYBREAK OIL AND GAS, INC.

 

                                                                                 By: /s/ JAMES F. WESTMORELAND

                                                                                           James F. Westmoreland, its

                                                                                           President, Chief Executive Officer and interim

                                                                                           principal finance and accounting officer

                                                                                          (Principal Executive Officer, Principal Financial

                                                                                           Officer and Principal Accounting Officer)

 

                                                                     Date:  January 12, 2012